Aqueous based well treatment fluids are commonly used in drilling, stimulation, completion and workover operations of subterranean formations. Treatment designs typically mandate such fluids to exhibit a certain level of viscosity. Viscosifying polymers are often used in such fluids to provide the requisite viscosity. For instance, the viscosifying polymers are used to thicken fluids to prevent their loss into the formation. In hydraulic fracturing, the viscosifying polymer provides the requisite viscosity for proppant to be suspended in the fracturing fluid and to be carried into the formation. In addition, the viscosifying polymer prevents the proppant from prematurely settling from the viscosified fluid.
Viscosifying polymers, when present in thermal insulating fluids, are used to prevent or minimize heat loss from production tubing. Such fluids are characterized by low thermal conductivity and convection velocity and are capable of thermally insulating the wellbore. In addition, such fluids, when added either into an annulus or riser, effectively reduce undesired heat loss from the production tubing. For instance, thermal insulating fluids reduce the heat loss from a hot annulus to a cold annulus by reducing the fluid thermal convection caused by the temperature differential between the high temperature environment of the inner annulus and the low temperature environment of the outer annuli. Such fluids are further capable of reducing the amount of heat transfer from the production tubing to the surrounding wellbore, outer annuli and riser. Heat loss from produced fluids due to conduction and convection can also be reduced by more than 90% when compared with conventional packer fluids.
Examples of viscosifying polymers used in well treatment fluids include synthetic polymers and polysaccharides such as acrylamide based polymers and copolymers, and guar and guar derivatives like hydroxypropyl guar, carboxymethylhydroxypropyl guar and carboxymethyl guar. Fracturing and thermal insulating fluids typically contain between from about 0.1 to 10 weight percent of such synthetic polymers or polysaccharides. Often, the fluid is brine-based. An exemplary thermal insulating fluid contains about 1 weight percent of carboxymethylhydroxypropyl guar, 25 volume percent of propylene glycol, 75 volume percent of brine, and optionally, a biocide, and a corrosion inhibitor.
Ancillary to the need for maintaining viscosity, the well treatment fluid is often desirable to have a sufficiently high density for the well treatment fluid to provide increased hydrostatic pressure and to be able to offset the relatively high pressure downhole, or to reduce required pump horsepower. It is desirous therefore to use brines with higher density than water to meet such demands. Exemplary of brines are sodium chloride, potassium chloride, calcium chloride, sodium bromide, calcium bromide, zinc bromide, potassium formate, cesium formate and sodium formate brines.
High density brines have particular applicability in deep wells, such as those that descend 15,000 to 30,000 feet (4,500 to 10,000 meters) or more below the earth's surface. In addition, high-density brines have been found to be capable of maintaining the requisite lubricity and viscosity of the well treatment fluid under extreme shear, pressure and temperature variances encountered during operations of deep wells.
For instance, fracturing fluids based on high-density brines are useful in deepwater and ultra-deepwater wellbore areas. Such areas require excessively high fracturing pressures. Fracturing fluids based on high-density brines exhibit exemplary hydrostatic head pressure to assist pump pressure.
The use of high-density brines in applications conducted at high temperatures and pressure is, however, difficult. Viscosifying polymers are hard to hydrate in high-density brines due to the high salt concentration and limited free water made available by the brine. While hydration of polymer in sodium salt based brines, such as sodium bromide brine and sodium chloride, may be achieved through manipulation of the pH of the brine, high concentration divalent ions such as Ca++ and Zn++ in higher density brines make hydration of viscosifying polymers (polysaccharides as well as synthetic polymers) extremely difficult. In case a polymer is hydratable in such brines, maintaining the gel stability at elevated temperature becomes rather challenging. The inability to satisfactorily hydrate the polymer in the presence of Ca++ and Zn++ has become a major obstacle in developing high-density brine based fracturing fluids.
Methodologies have therefore been sought for the use of well treatment fluids containing high-density brines, especially in deepwater wells.